System and method for harnessing energy from a pressurized gas flow to produce lng

ABSTRACT

A system includes a heat exchanger including a first inlet for receiving a first pressurized gas stream and a first outlet for outputting a chilled gas stream produced by the heat exchanger cooling the first pressurized gas stream. The system also includes a turbo expander connected to the first outlet of the heat exchanger for receiving the chilled gas stream from the heat exchanger and producing a partially liquified gas stream, the partially liquified gas stream comprising vapors and LNG. The system further includes at least one separator connected to the turbo expander, wherein the partially liquified gas stream is fed into the at least one separator, and the at least one separator separates the vapors from the LNG.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present disclosure is a Continuation-in-Part of U.S. patentapplication Ser. No. 17/470,438, entitled “Apparatus and Method forHarnessing Energy from a Wellbore to Perform Multiple Functions whileReducing Emissions,” filed on Sep. 9, 2021.

TECHNICAL FIELD

The present invention relates to separators, gas production units andmethods for separating gas from liquid, sand and debris being producedfrom oil and gas wells and more particularly to such devices used tofacilitate the production of natural gas and emissions-free or nearemissions-free energy for use in the production of LNG (liquid naturalgas), CNG (compressed natural gas), electricity, hydrogen and oxygen.

BACKGROUND

Modern natural gas and oil wells generate tremendous pressure duringearly production, in some cases approaching 20,000 psig. Transportingnatural gas via pipeline at these pressures is unfeasible not onlybecause of the enormous wall thickness the pipeline would need, but alsobecause partially depleted wells that share the same pipeline usuallycannot produce at these pressures. In the United States, transmissionpipelines usually operate at around 1,000 psig, and gathering pipelinesoften operate at pressures significantly below this. Pipelines,compressors, and processing equipment are commonly designed to handlepressures within this range, and conventional production and flowbackequipment is designed to reduce wellhead gas pressure to around 1,000psig or less; any oil, water, sand or debris is separated from the gasand deposited in tanks on location at near-atmospheric pressure.

A choke valve is conventionally used to reduce the fluid productionstream (all the gas and liquids produced by the well) from wellheadpressure to pipeline pressure. At high wellhead pressures, the fluidproduction stream must be heated before or after the choke to counteractthe Joule-Thomson (JT) effect, which would otherwise cause problemsdownstream (ice and clathrate hydrate formation, low-temperatureembrittlement of steel equipment, etc.). This is conventionallyaccomplished using a glycol-bath heater fueled by a portion of theproduced gas; burning this fuel generates undesirable emissions andconsumes gas that would otherwise be sold.

Friction causes gas to lose pressure as it travels through a pipeline;transmission pipelines operate booster compressors to counteract thiseffect, keeping the gas at around 1,000 psig. Yet many compressednatural gas (CNG) facilities take gas from distribution pipelinesoperating below 100 psig. For a well producing at 3,600 psig or greater,it seems very inefficient to throttle the gas to around 1,000 psig,compress it repeatedly to keep it near 1,000 psig as it travels throughthe pipeline, throttle it again to less than 100 psig at a pressureletdown station, and then compress it back up to 3,600 psig, thecustomary pressure of CNG. In the same way, it seems inefficient to heathigh-pressure wellhead gas to counteract the JT effect and then chill itfrom ambient temperature to around −250° F. at a liquefied natural gas(LNG) facility. However, this is all standard practice.

Many natural gas well sites use two primary devices to condition eachwell's fluid production stream. The first is a sand separator, a vesselthat removes sand and debris from the fluid production stream to preventfouling in (and damage to) downstream equipment. The second is a gasproduction unit (GPU), which reduces the fluid production stream topipeline pressure (the aforementioned choke valve and glycol-bath heaterare part of the GPU) and separates liquids from the gas. A typical gasproduction facility including a sand separator 10 and a GPU 20 is shownin FIG. 1 .

Existing sand separators and GPUs have many limitations that increasethe cost of flowback and production operations. Neither can handle thehigh rates of sand and liquid produced during flowback, so temporaryflowback equipment (usually rented from a third party) must be usedbefore the permanent sand separator and GPU are installed. Sandseparators also lack level indication and must be manually drained;because sand production rates are unpredictable, it is impossible toestablish an optimized draining schedule for any given well, and sandseparators must be drained far more often than would be hypotheticallyrequired. Additionally, downstream equipment must be fitted with thickerpipe walls to allow for erosion due to sand carryover in the fluidproduction stream.

The lack of real-time feedback or precision control of the GPU drainalso increases the risk of liquid carryover into the pipeline, which cancause operational problems, as well as gas blowby to production tanks,which creates fugitive emissions and poses a safety hazard. At times, athird “polishing” separation vessel is installed downstream of the GPUto compensate for the GPU's failure to separate all liquids from theproduced gas.

In contrast, production equipment would ideally use a single separationvessel, accurate and reliable liquid level indication, and automateddrain valves that ensure complete and consistent separation of solidsand liquids from the produced gas, even during flowback operations. Itwould also have a smaller footprint to allow for more flexibility insite design.

SUMMARY

Embodiments of the present disclosure are generally directed to a systemincluding a heat exchanger, a turbo expander, and at least oneseparator. In some non-limiting examples, the heat exchanger includes afirst inlet for receiving a first pressurized gas stream, and a firstoutlet for outputting a chilled gas stream produced by the heatexchanger cooling the first pressurized gas stream. The turbo expanderis connected to the first outlet of the heat exchanger for receiving thechilled gas stream from the heat exchanger and producing a partiallyliquified gas stream. The partially liquified gas stream includes vaporsand LNG. The at least one separator is connected to the turbo expander.The partially liquified gas stream is fed into the at least oneseparator, and the at least one separator separates the vapors from theLNG.

In some non-limiting embodiments, the heat exchanger further includes atleast one vapor inlet in the heat exchanger connected to the at leastone separator for receiving vapors from the at least one separator.

In some non-limiting embodiments, the system further includes: at leastone vapor outlet for outputting the vapors from the heat exchanger, andat least one compressor connected between the at least one vapor outletof the heat exchanger and a pipeline for compressing the vapors outputfrom the heat exchanger to a pressure suitable for the pipeline.

In some non-limiting embodiments, the turbo expander is coupled to theat least one compressor, wherein the turbo expander supplies power tothe at least one compressor.

In some non-limiting embodiments, the system further includes a coolerconnected between the at least one compressor and the pipeline.

In some non-limiting embodiments, the at least one compressor is amulti-stage compression assembly comprising multiple compressorsconnected in series, and the at least one separator is a multi-stageseparation assembly comprising multiple separators connected in series.

In some non-limiting embodiments, the at least one vapor inlet includesmultiple vapor inlets each connected to one of the multiple separators,the at least one vapor outlet includes multiple vapor outlets eachconnected between a corresponding one of the multiple vapor inlets and acorresponding one of the multiple compressors, and at least oneinterstage vapor mixer is connected between one of the multiple vaporoutlets and the corresponding one of the multiple compressors for mixingvapors output from the one of the multiple vapor outlets with compressedvapors output from an adjacent compressor.

In some non-limiting embodiments, the system further includes: a feedsplitter upstream of the heat exchanger for splitting an initial gasstream into the first pressurized gas stream and a second pressurizedgas stream, a second turbo expander connected between the feed splitterand a second inlet of the heat exchanger, wherein the second turboexpander receives the second pressurized gas stream and outputs anexpanded gas stream to the second inlet, and a pipeline connected to asecond outlet of the heat exchanger, the second outlet outputting aheated gas stream produced by the heat exchanger heating the expandedgas stream.

In some non-limiting embodiments, the system further includes at leastone compressor connected between the heat exchanger and the pipeline forproviding compressed gas to the pipeline, and the heat exchanger furtherincludes: at least one vapor inlet for receiving vapors from the atleast one separator, and at least one vapor outlet for outputting thevapors from the heat exchanger, wherein the at least one compressor isconnected to the at least one vapor outlet.

In some non-limiting embodiments, the at least one compressor is coupledto one or both of the turbo expander and the second turbo expander,wherein one or both of the turbo expander and the second turbo expandersupplies power to the at least one compressor.

Other embodiments of the present disclosure are directed to a method.The method includes receiving a first pressurized gas stream into a heatexchanger, cooling the first pressurized gas stream via the heatexchanger to produce a chilled gas stream output from the heatexchanger, expanding the chilled gas stream via a turbo expanderconnected to the first outlet to produce a partially liquified gasstream comprising vapors and LNG, and separating the vapors from the LNGvia a separator connected to the turbo expander.

In some non-limiting embodiments, the method further includes receivingthe vapors from the at least one separator into at least one vapor inletof the heat exchanger, and cooling the first pressurized gas stream viaheat transfer between the first pressurized gas stream and the vapors inthe heat exchanger.

In some non-limiting embodiments, the method further includes outputtingthe vapors from the heat exchanger via at least one vapor outlet of theheat exchanger, and compressing the vapors output from the heatexchanger via at least one compressor to output a compressed gas towarda pipeline at a pressure suitable for the pipeline.

In some non-limiting embodiments, the method further includes supplyingpower generated by the turbo expander to the at least one compressor foroperating the at least one compressor.

In some non-limiting embodiments, the method further includes coolingthe compressed gas output from the at least one compressor via a coolerconnected between the at least one compressor and the pipeline.

In some non-limiting embodiments, the at least one compressor is amulti-stage compression assembly comprising multiple compressorsconnected in series, and the at least one separator is a multi-stageseparation assembly comprising multiple separators connected in series.

In some non-limiting embodiments, the at least one vapor inlet comprisesmultiple vapor inlets each connected to one of the multiple separators,the at least one vapor outlet comprises multiple vapor outlets eachconnected between a corresponding one of the multiple vapor inlets and acorresponding one of the multiple compressors, and the method furtherincludes mixing vapors output from the one of the multiple vapor outletswith compressed vapors output from a compressor adjacent thecorresponding one of the multiple compressors.

In some non-limiting embodiments, the method further includes splittingan initial gas stream into the first pressurized gas stream and a secondpressurized gas stream, reducing a pressure of the second pressurizedgas stream via a second turbo expander to produce an expanded gas streamprovided to the heat exchanger, cooling the first pressurized gas streamvia heat transfer between the first pressurized gas stream and theexpanded gas stream in the heat exchanger, and outputting a heated gasstream produced by the heat exchanger heating the expanded gas streamtoward a pipeline at a pressure suitable for the pipeline.

In some non-limiting embodiments, the method further includes receivingvapors from the at least one separator into the heat exchanger,outputting the vapors from the heat exchanger after the vapors areheated, and compressing the vapors output from the heat exchanger via atleast one compressor to output a compressed gas toward the pipeline atthe pressure suitable for the pipeline.

In some non-limiting embodiments, the method further includes supplyingpower generated by one or both of the turbo expander and the secondturbo expander to the at least one compressor for operating the at leastone compressor.

These and other features and characteristics will become more apparentupon consideration of the following description and the appended claimswith reference to the accompanying drawings, all of which form a part ofthis specification, wherein like reference numerals designatecorresponding parts in the various figures. It is to be expresslyunderstood, however, that the drawings are for the purpose ofillustration and description only and are not intended as a definitionof the limits of the disclosure. As used in the specification and theclaims, the singular forms of “a”, “an”, and “the” include pluralreferents unless the context clearly dictates otherwise.

BRIEF DESCRIPTION OF THE DRAWINGS

For a more complete understanding of the present disclosure and itsfeatures and advantages, reference is now made to the followingdescription, taken in conjunction with the accompanying drawings, inwhich:

FIG. 1 is a perspective view of a prior art gas production facility,including a conventional sand separator and GPU;

FIG. 2 is a perspective view of a separator according to an embodimentof the present disclosure;

FIG. 3 is a front view of the separator of FIG. 2 ;

FIG. 4 is a side view of the separator of FIG. 2 ;

FIG. 5 is a perspective view of the main body of the separator of FIG. 2;

FIG. 6 is a side cross-sectional view of the separator of FIG. 2 ;

FIG. 6A is a side cross-section view of a horizontal orientation of theseparator of FIG. 2 .

FIG. 7 is a detail view of the inlet port of the separator of FIG. 2 ;

FIG. 7A is a detail view of an alternate embodiment of an inlet port ofthe separator of FIG. 2 ;

FIG. 8 is a fluid schematic of the separator of FIG. 2 ;

FIG. 9 is a fluid schematic of a dual dump valve arrangement for usewith the separator of FIG. 2 ;

FIG. 10 is a schematic partial cross-sectional view of a separatoraccording to another embodiment of the present disclosure;

FIG. 11 is a schematic partial cross-sectional view of a separatoraccording to another embodiment of the present disclosure;

FIG. 12 is a schematic partial cross-sectional view of a separatoraccording to another embodiment of the present disclosure;

FIG. 13 is a perspective view of a gas processing facility according toan embodiment of the present disclosure;

FIG. 14 is a rear view of the line heater and choke of FIG. 13 ;

FIG. 15 is a flow diagram of a process for operating the separator ofFIG. 2 ;

FIG. 16 is a side cross-sectional view of the separator according toanother embodiment of the present disclosure;

FIG. 17 is a schematic diagram illustrating a separator performingflowback operations according to an embodiment of the presentdisclosure;

FIG. 17A is a schematic diagram illustrating an embodiment employingdual separators for performing flowback operations according to anembodiment of the present disclosure;

FIG. 18 is a schematic block diagram of a system according to anembodiment of the present disclosure using a separator to provide apressurized gas stream to various downstream components;

FIG. 19 is a schematic block diagram of a system according to anotherembodiment of the present disclosure using a separator to provide apressurized gas stream to various downstream components;

FIG. 20 is a schematic block diagram of a system according to yetanother embodiment of the present disclosure using a separator toprovide a pressurized gas stream to various downstream components;

FIG. 21 is a schematic block diagram of a system according to yetanother embodiment of the present disclosure using two separatorsconnected in series to provide a pressurized gas stream to variousdownstream components;

FIG. 22 is a schematic block diagram of a system according to yetanother embodiment of the present disclosure using a pressurized gasstream to perform one or more operations including producing LNG;

FIG. 23 is a detailed schematic diagram of an embodiment of the systemin FIG. 22 having one stage of compression; and

FIG. 24 is a detailed schematic diagram of another embodiment of thesystem in FIG. 22 having multiple compression stages.

DETAILED DESCRIPTION

For purposes of the description hereinafter, the terms “upper”, “lower”,“right”, “left”, “vertical”, “horizontal”, “top”, “bottom”, “lateral”,“longitudinal”, and derivatives thereof shall relate to the disclosureas it is oriented in the figures. However, it is to be understood thatthe disclosure may assume alternative variations and step sequences,except where expressly specified to the contrary. It is also to beunderstood that the specific devices and processes illustrated in theattached drawings and described in the following specification aresimply exemplary aspects of the disclosure. Hence, specific dimensionsand other physical characteristics related to the aspects disclosedherein are not to be considered as limiting.

As used herein, the term “psi” means pounds per square inch.

As used herein, the term “at least one of” is synonymous with “one ormore of”. For example, the phrase “at least one of A, B, and C” meansany one of A, B, and C, or any combination of any two or more of A, B,and C. For example, “at least one of A, B, and C” includes one or moreof A alone; or one or more B alone; or one or more of C alone; or one ormore of A and one or more of B; or one or more of A and one or more ofC; or one or more of B and one or more of C; or one or more of all of A,B, and C. Similarly, as used herein, the term “at least two of” issynonymous with “two or more of”. For example, the phrase “at least twoof D, E, and F” means any combination of any two or more of D, E, and F.For example, “at least two of D, E, and F” includes one or more of D andone or more of E; or one or more of D and one or more of F; or one ormore of E and one or more of F; or one or more of all of D, E, and F.

Referring to FIGS. 2-7 , embodiments of the present disclosure aredirected to a sand and liquid separator 1000 (hereinafter “separator1000”) particularly adapted for use at natural gas wells. The main body1100 of the separator 1000 is generally a hollow vessel which defines aninterior chamber 1010. In the embodiment shown in the FIGS. 2-8 , themain body 1100 is constructed of an upper vessel section and a lowervessel section, which together define a continuous interior chamber1010. However, it is to be understood that the main body 1100 could beconstructed from any number of sections, including one continuous,unitary section as shown in FIGS. 10-12 and 16 . The main body 1100 ispreferably constructed from a strong, rigid material such as steeldesigned, configured, or rated to operate at an incoming pressure of gasflowing directly or indirectly (e.g. through a choke) from the wellbore.In some embodiments, the separator 1000 may be rated, designed, orconfigured for, or be capable of, operating at gas pressures greaterthan approximately 1500 psi, or greater than approximately 2,500 psi, orgreater than approximately 5,000 psi. In some embodiments, the separator1000 may be rated, designed, or configured for, or be capable of,operating at gas pressures as high as or greater than an unregulatedpressure at which gas flows from the wellbore. For example, unregulatedgas pressure at the wellhead of Marcellus Shale formation wells may beapproximately 5,000 psi, and unregulated gas pressure at the wellhead ofUtica Shale formation wells may be approximately 10,000 psi. In otherembodiments, the separator 1000 may be rated, designed, or configuredfor, or be capable of, operating at regulated gas pressures. Forexample, the gas pressure of a Utica Shale formation well may beregulated down from approximately 10,000 psi at the wellhead toapproximately 5,000 psi before being fed to the separator 1000. Such apressure regulation, which may be utilized to prevent damage to orfailure of the various components of the separator 1000 describedherein, may be achieved by a choke or other device disposed inlinebetween the wellbore and the separator 1000. In some embodiments, theseparator 1000 and the various components thereof may be designed tomeet various industry standards for pressure vessels or pressure and/ortechnical limitations associated with instrumentation described herein.As those of ordinary skill in the art will appreciate, modifications toexisting instruments and other system components (e.g., the main body1100 of the separator 1000) can be made to accommodate the highpressures of formations such as the Utica Shale formation without theneed of equipment to regulate the pressure down from that coming out ofthe wellbore. As those of ordinary skill in the art will appreciate, theseparator 1000 can be oriented horizontally rather than vertically, asshown in FIG. 6A.

In addition, the disclosed separator 1000 allows for separation offluid, sand and debris from the gas stream at pressures available at thewellbore, prior to gas pressure reduction. It is advantageous tomaintain high gas pressure of the gas removed of fluid, sand, anddebris, as this pressurized stream of gas may be used for the productionof compressed natural gas (CNG), liquefied natural gas (LNG),electricity, hydrogen and/or oxygen. These products may be producedindividually or simultaneously in any combination without compressionand free of emissions, with or without also providing natural gas to apipeline.

In embodiments in which the main body 1100 is constructed of multiplesections, the various sections may be connected to one another using anysuitable fastening method or device, such as mechanical fasteners (e.g.bolts or rivets), a welded joint, or the like. The connection betweenthe various sections should be sufficiently tight to prevent the escapeof high pressure gas and other materials from the interior chamber 1010to the outside environment. The main body 1100 may be supported in agenerally vertical position by a frame 1002.

A plurality of inlets and outlets (e.g., in the form of connecting portsand/or flanges) may be provided in the main body 1100 to facilitate flowof liquid, sand, and other debris through the separator 1000. An inlet(e.g., inlet port 1020 provided in the main body 1100) may allow flowinto the interior chamber 1010 from a wellbore. The inlet port 1020 maybe fluidly connected to the wellbore by rigid or flexible pipe, and flowto the inlet port 1020 may be regulated by one or more valves or thelike (see FIG. 8 ). As shown in FIGS. 6-7 , the inlet port 1020 mayinclude a tube 1022 extending into the interior chamber 1010, with aterminal end of the tube 1022 being partially obstructed by a baffle1024. Gas, liquid, sand and other debris entering the interior chamber1010 flows through the tube 1022, in the direction of arrow A, and anysolid and/or liquid contaminants carried by the gas may be deflected bythe baffle 1024 toward a bottom of the interior chamber 1010. Suchcontaminants may include, for example, sand, water, oil, rock, and metalfragments.

An outlet (e.g., liquid, sand, and debris outlet port 1030) may beprovided at or near a lower portion of the interior chamber 1010. Theoutlet port 1030 may be fluidly connected to a valve 2000 which may beperiodically and/or continuously opened and closed to drain liquid andsolid contaminants collected at the bottom of the interior chamber 1010.The valve 2000 may be mounted remotely from the separator 1000 by rigidor flexible pipe. The valve 2000 may feed into a waste holding tank 3000(see FIG. 8 ), also via rigid or flexible pipe, for holding contaminantsremoved from the gas until the contaminants can be safely processed fordisposal.

As shown in FIG. 8 , the holding tank 3000 may be fluidly coupled to oneor more pieces of downstream processing equipment 3002. The downstreamprocessing equipment may include, for example, one or more separationcomponents used to separate the different constituents of the liquid,sand, and/or debris output from the separator 1000. The downstreamprocessing equipment 3002 may, in certain embodiments, comprise adedicated sand vessel configured to remove sand from the waste fluid, agun barrel-type separator, or a pressurized four-phase (e.g., gas, sand,water and oil) separation skid equipped with a sand removal device. Useof a pressurized four-phase separation skid may allow the well pressureto provide the motive force for removing fluid from the well pad,instead of diesel transfer pumps.

The valve 2000 may be a dump valve, and more particularly a hardeneddump valve 2000. It should be noted, however, that any desired type ofvalve 2000 may be used to output liquid, sand, and/or debris from thelower portion of the interior chamber 1010. The valve 2000 may be apiston valve, a ball valve, a butterfly valve, a gate valve, a chokevalve, a needle valve or the like suitable for operation at pressures upto, for example, 5,000 psi. The valve 2000 may include an electrical,hydraulic, or pneumatic actuator such as an electric motor, solenoid,hydraulic actuator, pneumatic actuator, or combinations thereof suchthat opening and closing of the valve 2000 can be performedautomatically by an electronic controller 4000 (see FIG. 8 ). As such,the valve 2000 may be an electronically controlled valve. In certainembodiments, the valve 2000 may include a fast-acting electricallyactuated linear valve actuator used to rapidly transition the valve 2000between open and closed positions and/or to one or more intermediatepositions between the open and closed positions. The valve actuator maybe capable of transitioning the valve 2000 between a fully open positionand a fully closed position in less than 2.0 seconds, more particularlyless than 1.0 second, or more particularly less than 0.5 seconds.

In some embodiments, the valve 2000 may be configured to be selectivelyoperated in a hand mode. In some embodiments, the controller thatcontrols the valve 2000 may be programmed to allow operation of thevalve 2000 in a hand mode. “Hand mode” is a manual operation mode bywhich the valve 2000 may be selectively opened or closed manually eitherby rotating the wheel handle or by the user pressing buttons on thevalve to open and close it. This may allow for equalization across thevalve 2000 to drain the line segment for maintenance of the valve. Insome embodiments, the valve 2000 may be equipped with a bleed valve forperforming maintenance on the valve 2000.

In some embodiments, the valve 2000 may be equipped with or coupled to apressure pilot device configured to automatically initiate closure ofthe valve 2000 upon encountering pressure in the valve line above apredetermined threshold. This may prevent high pressure from damagingthe holding tank 3000 and/or other downstream components 3002, forexample, in the case of gas breaking through the liquid, sand, anddebris outlet 1030 of the separator 1000. The pressure pilot deviceassociated with the valve 2000 may thus provide a failsafe for theseparator system. In other embodiments, a pressure transducer 4053 maybe disposed in the valve line downstream of the valve 2000 andconfigured to detect pressure in the line and communicate the detectedpressure to the controller 4000, as shown in FIG. 8 . The controller4000 may then send an electronic command to close the valve 2000 toprevent high pressure from damaging downstream components. Both anactive pilot safety valve and/or pressure transducer may be used.Because of the critical nature of this operation, redundant pilot safetyvalves and/or pressure transmitters may be used.

As illustrated in FIG. 8 , in some embodiments a valve position sensor4050 may be disposed proximate or incorporated into the valve 2000. Thevalve position sensor 4050 may include at least one of a visualdetection sensor, a motion sensor, a pressure sensor, a strain gauge, orany other type of sensor configured to indicate either a relativeposition of the valve 2000, or simply whether the valve 2000 is fullyclosed. The valve position sensor 4050 may indicate an operationalposition of the valve 2000. The valve position sensor 4050 may beconnected to the controller 4000 to provide feedback of the operationalposition of the electronically controlled valve 2000 to the controller4000. This valve position feedback may be used by the controller 4000 toidentify the presence of an obstruction to the valve 2000 (e.g., in theevent that the valve 2000 fails to completely close). Upon identifyingan obstruction to the valve 2000, the controller 4000 may output anotification to a user interface 4002 coupled to the controller 4000 sothat a user may manually remove the obstruction or switch operation ofthe valve 2000 to a backup valve. In other embodiments, the controller4000 may output a command to a piece of equipment designed toautomatically remove obstructions from the valve 2000. The obstructioncan be cleared by initiating a rapid open/close cycle. In at least oneembodiment, the feedback to the controller 4000 can be used to detectwash out (erosion) where the valve is closed but fluid is still leakingpast the valve. A second valve or emergency shutdown (“ESD”) valve 4057may be located downstream of valve 2000.

In some embodiments, two or more valves 2000 may be provided in parallelto one another due to the critical nature of this component. If one ofthe two valves 2000 fails, leaks, erodes or is nonoperational (e.g.undergoing maintenance), the second valve 2000 may be used to operatethe separator 1000. FIG. 9 schematically illustrates the arrangement oftwo valves 2000A and 2000B in parallel. The primary valve 2000A andsecondary valve 2000B may be identical valves, so that fewer maintenancecomponents and spare parts are needed to perform maintenance and repairson the valves 2000. As illustrated, the valves 2000A and 2000B may becoupled to independent strainers (or junk catchers) 4110A and 4110B,respectively, provided upstream of the valves 2000A and 2000B to capturedebris. The valves 2000A and 2000B may feed into the same waste holdingtank 3000, as illustrated, or into different waste holding tanks. Bothvalves 2000A and 2000B may be electronically controlled and connected tothe controller 4000. The valves 2000A and 2000B may be electronicallycontrolled by the controller 4000 to provide a fixed flow rate, e.g.,150 barrels of water per hour rather than controlled to maintain acertain level of liquid in the interior chamber 1010 of the vessel. Asthose of ordinary skill in the art will appreciate, this method ofoperation may be employed, e.g., where little to no gas is present.

Turning back to FIGS. 2-8 , in some embodiments, a plurality of bridleports 1040 a-1040 d may be provided in the upper vessel section 1100 andmay be configured to connect to a bridle 1300. The bridle 1300 mayinclude a tube 1310 and a plurality of connecting flanges 1320 a-1320 d.As illustrated, the tube 1310 may be a vertical tube 1310 (i.e., thetube axis is oriented vertically). Each of the connecting flanges 1320a-1320 f may connect to a corresponding one of the bridle ports 1040a-1040 f, such that fluid can flow freely between the tube 1310 and anyof the bridle ports 1040 a-1040 f via the connecting flanges 1320 a-1320f. Because fluid can flow freely between the interior chamber 1010 andthe bridle 1300 via the bridle ports 1040 a-1040 f, a liquid level inthe tube 1310 of the bridle 1300 self-equalizes with a liquid level inthe interior chamber 1010. As such, the liquid level in the interiorchamber 1010 may be ascertained by measuring the liquid level in thebridle 1300. The bridle 1300 also helps to protect the instruments fromgas bubbles in the interior chamber 1010, which can cause theinstruments to record inaccurate readings.

As shown in the accompanying drawings, a representative embodiment ofthe separator 1000 includes six bridle ports 1040 a-1040 f and sixcorresponding connecting flanges 1320 a-1320 f. As those of ordinaryskill in the art will appreciate, the bridle 1300 may include more thansix bridle ports or a lesser number. The bridle port third from the top1040 c may correspond to a high liquid level within the interior chamber1010, and the lowermost bridle port 1040 f may correspond to a lowliquid level within the interior chamber 1010. During operation, thevalve 2000 may be periodically and/or continuously opened and closed, ormodulated between an opened and closed position, to maintain the liquidlevel within the interior chamber 1010 at a desired level, for examplebetween the bridle port third from the top 1040 c and the lowermostbridle port 1040 f. The two intermediate bridle ports 1040 d, 1040 ebetween the bridle port third from the top 1040 c and the lowermostbridle port 1040 f may facilitate equalization of the liquid level inthe interior chamber 1010 with the liquid level in the bridle 1300. Thebridle port 1040 a prevents the formation of a gas pocket from formingat the top of the bridle 1300 and allowing the liquid level sensor 1400to take measurements along the entire length of the bridle 1300 andvessel. The bridle ports 1040 a-f may be spaced vertically apart fromone another and be of sufficient cross-sectional area to ensure that theliquid level within the bridle 1300 can rapidly equalize with the liquidlevel in the interior chamber 1010. That is, the bridle ports 1040 a-fallow sufficient liquid flow into the bridle 1300 to minimize time delayin equalization of the liquid level within the bridle 1300 to the liquidlevel in the interior chamber 1010. It is to be understood that theseparator 1000 may include more or fewer bridle ports, and acorresponding number of connecting flanges, than are shown in thedrawings in order to reduce liquid level equalization time in the bridle1300. Moreover, the bridle ports may have increased cross sectional areain order to reduce liquid level equalization time in the bridle 1300.The bridle 1300 may include a cleanout valve 1330 that may be used toevacuate sand or other particulate material that may become trapped inthe bridle 1300. The cleanout valve 1330 may be coupled to a drain line1332 extending from the bridle 1300. In FIGS. 2-4, 6, and 6A, the drainline 1332 is illustrated as leading back into the interior chamber 1010of the separator. In other embodiments (e.g., as shown in FIG. 8 ), thedrain line 1332 may be a flow path extending from the bridle 1300 to alocation downstream of the valve 2000 for outputting the sand or otherparticulate material to the waste holding tank 3000 or anotherdownstream location.

In some embodiments, the drain line 1332 of the bridle 1300 may be atleast partially tilted with respect to a vertical direction, as shown inFIG. 10 . In at least one example the drain line 1332 is installed at a45° angle from the vertical axis of the bridle 1300. As shown in FIGS. 8and 10 , the lower drain line 1332 may be tilted back into the interiorchamber 1010 of the separator 1000. The tilted drain line 1332 of thebridle 1300 may prevent buildup of sand or other particulate material inthe bridle 1300, since the tilted axis of the drain line 1332 and itsintersection with the interior chamber 1010 automatically urges any sandor particulate material to settle back into the bottom of the interiorchamber 1010 for eventual release through the outlet 1030.

In some embodiments, the bridle may be equipped with cleanout out portsor plugs, 1340 a-1340 f, as shown in FIG. 6 . These ports allow for thecleaning of the equalization ports/piping, in the event sand or debriscollects in the horizontal pipe segments associated with equalizationports 1320 a-f.

A liquid level sensor 1400 may be inserted in the tube 1310 of thebridle 1300 to determine the liquid level in the tube 1310 which, asnoted above, is automatically equalized with the liquid level in theinterior chamber 1010, by flow through the bridle ports 1040 c, 1040 d,1040 e, 1040 f. The liquid level sensor 1400 may be in electroniccommunication with the controller 4000 that actuates the valve 2000. Inparticular, the controller 4000 may open and close the valve 2000, andin particular modulate between open and closed states, based on themeasured liquid level in the bridle 1300. In an embodiment, the liquidlevel sensor 1400 may be a guided wave radar sensor including a probethat extends generally parallel to an axis of the tube 1310 so as to beimmersed in any liquid within the bridle 1300. Examples of suitable,commercially available guided wave radar sensors include the Eclipse®Model 706 by Orion® Instruments. In other embodiments, the liquid levelsensor 1400 may be a capillary tube, a differential pressure sensor, anultrasonic sensor, or the like. However, guided wave radar may bedesired as that technology can determine differences as fine as 0.10inches of water column in real-time and is effective throughout the lifeof the well down to, for example, 2 psi. In comparison to a differentialpressure sensor, the guided wave radar may be desired because it isunaffected by the ever-changing gravity of the fluid. In someembodiments, the liquid level sensor 1400 may be configured to determinea stratification level between water and oil in the bridle 1300.

In some embodiments, the separator 1000 may not include a bridle at all.For example, as shown in FIG. 11 , the separator 1000 may include aliquid level sensor 1400 inserted directly into an upper portion of theinterior chamber 1010 of the separator 1000 to determine the liquidlevel in the separator 1000. The liquid level sensor 1400 may be aguided wave radar sensor, as described above. In still otherembodiments, the separator 1000 may include both a bridle 1300 with afirst liquid level sensor 1400 disposed therein (as shown in FIG. 8 )and a second liquid level sensor 1400 disposed in the interior chamber1010 (as shown in FIG. 11 ) to provide redundant measurements of theliquid level in the separator 1000.

With continued reference to FIGS. 2-7 , a gas outlet (e.g., gas outletport 1050) may be provided in the main body 1100 through which gas mayflow out of the separator 1000 to downstream components of the facility,such as a line heater or molecular dryer. The gas outlet port 1050 maybe fluidly connected to the downstream components, for example, by rigidor flexible pipe. The gas outlet port 1050 may be located verticallyabove the uppermost bridle port 1040 a, and therefore above the intendedliquid level of the interior chamber 1010, such that no liquid flows outof the gas outlet port 1050 during normal operation. In someembodiments, a mist extractor 1052 may be provided within the interiorchamber 1010 below the outlet port 1050 to prevent very fine waterdroplets/aerosols from reaching the outlet port 1050 and exiting theseparator 1000. In some embodiments, a diffuser 1054 (see FIG. 6 ) maybe provided within the interior chamber 1010 to allow gas to more easilytravel upward within the interior chamber 1010.

In some embodiments, the gas outlet port 1050 may extend through a topof the main body 1100 of the separator 1000, as shown in FIGS. 2-7 ,thereby enabling a maximum length of the bridle 1300 and/or a maximumlength between the upper and lower limits for the liquid level in theseparator 1000. In other embodiments, as shown in FIG. 12 , the gasoutlet port 1050 may extend through a side wall 1056 of the main body1100 of the separator 1000.

In some embodiments, a gas measurement device 1057, as shown in FIG. 8may be installed to measure gas volumes exiting separator 1000. Themeasurement device may be an ultrasonic, orifice, VCone, or any devicecapable of measuring gas volumes exiting the separator 1000. Bymeasuring the gas flow immediately downstream of separator 1000, gasfrom other wells that have been measured can be comingled. This is ofparticular importance where each of the wells are on different gasleases or have different gas ownership. This also allows multiple wellsto be tied together to collectively harness their energy through commondownstream equipment.

An upper sensor port 1060 may be provided in the main body 1100 of theseparator 1000 and may receive an upper limit sensor 1064, such as alimit switch, float switch, thermal dispersion switch, or the like. Theupper sensor port 1060 may be located vertically above the uppermostbridle port 1040 a and vertically below the gas outlet port 1050. Insome embodiments, the upper limit sensor 1064 may be located above anuppermost point at which the liquid level sensor 1400 can detect liquid.The upper limit sensor 1064 may be used to detect the presence ofliquid, and may thus serve as an auxiliary device, in addition to theliquid level sensor 1400, for determining if the liquid level is above apredetermined high point in the interior chamber 1010. The upper limitsensor 1064 may be in electronic communication with the controller 4000,and the controller 4000 may be programmed or configured to initiate ashutdown procedure if liquid is detected by the upper limit sensor 1064.

Similarly, a lower sensor port 1064 may be provided in the main body1100 of the separator 1000 and may receive a lower limit sensor 1066,such as a limit switch, float switch, thermal dispersion switch, or thelike. The lower sensor port 1062 may be located vertically below thelowermost bridle port 1040 f and vertically above the inlet port 1020.In some embodiments, the lower limit sensor 1066 may be located below alowermost point at which the liquid level sensor 1400 can detect liquid.The lower limit sensor 1066 may be used to detect the presence ofliquid, and may thus serve as an auxiliary device, in addition to theliquid level sensor 1400, for determining if the liquid level is below apredetermined low point in the interior chamber 1010. The lower limitsensor 1066 may be in electronic communication with the controller 4000,and the controller 4000 may be programmed or configured to initiate ashutdown procedure if liquid is not detected by the lower limit sensor1066.

In the embodiments shown in FIGS. 2-6 and 8 , the upper sensor port 1060and the lower sensor port 1064 are provided in the main body 1100 of theseparator 1000. FIG. 16 shows an alternative embodiment in which theupper sensor port 1060 and the lower sensor port 1064 are provided inthe bridle 1300. The functionality of the upper sensor port 1060 and thelower sensor port 1064, along with the associated upper and lower limitsensors 1064, 1066, are the same in the embodiment shown in FIGS. 2-6and 8 and the embodiment shown in FIG. 16 .

With reference to FIG. 8 , a density sensor port may be provided in themain body 1100 of the separator 1000 and may receive a density sensor4052, such as a Coriolis meter or the like. The density sensor port maybe located vertically above the lower sensor port 1064 and verticallybelow the lowermost bridle port 1040 f The density sensor 4052 may beused to detect the density or specific gravity of the fluid (liquid) inthe main body 1100 of the separator 1000. The density sensor 4052 may bein electronic communication with the controller 4000, and the controller4000 may be programmed or configured to open, close, or modulate theshutoff valve 4120 depending on the detected flow rate and/or sandconcentration of the liquid, sand, and debris in the separator 1000.

A second density sensor 4054 may be ported to the valve line upstream ofthe valve 2000, as illustrated in FIG. 8 . The second density sensor4054 may comprise the same type of sensor (e.g., a Coriolis meter) asthe density sensor 4052 in the separator 1000. The second density sensor4054 may be used to detect the flow rate and/or density or specificgravity of the fluid (liquid) from the separator 1000. The densitysensor 4054 may be in electronic communication with the controller 4000,and the controller 4000 may be programmed or configured to open, close,or modulate the shutoff valve 4120 depending on the flow rate and/ordensity or specific gravity of the fluid (liquid) in the separator 1000(detected by sensor 4052) in comparison to the flow rate and/or sandconcentration of the liquid, sand, and debris output from the separator1000. By comparing the density measured by density sensor 4052 to thedensity measured by density sensor 4054 an accurate estimation of sandconcentration can be ascertained thereby helping to understand in realtime the density of fluid flowing through the separator 1000. Thedetermined density and flow rates of fluid flowing through the separator1000 may be used to provide volume control of production out of thewell. It can also serve as a safety device shutting in the system if gasis present.

Referring again to FIGS. 2-6 , a relief valve 1070 may be provided at ornear the top of the upper vessel section 1100 and may be configured toopen at a predetermined pressure to allow pressurized gases to escapefrom the interior chamber 1010. The pressure at which the relief valve1070 is configured to open may be selected to prevent damage to theseparator 1000 and/or downstream components from excess gas pressure.For example, the relief valve 1070 may be configured to open if the gaspressure in the interior chamber 1070 exceeds the maximum operatingtemperature of the separator 1000, for example approximately 5,000 psi.The relief valve 1070 may be passive, e.g. having a spring that deflectsat a predetermined crack pressure, or may be actively controlled by thecontroller 4000.

With continued reference to FIGS. 2-6 , the relative vertical locationsof the various ports may optimize performance of the separator 1000. Forexample, the inlet port 1020 may be located below the bridle ports 1040a-1040 f, with the baffle 1024 directing inflow downward, so thatcontaminants do not flow toward and become trapped in the bridle 1300.The inlet port 1020 may also be located below the gas outlet port 1050so that less dense gas rises above relatively more dense water, suchthat only the gas exits the separator 1000 via the gas outlet port 1050.Moreover, the gas outlet port 1050 may be located at the top of the mainbody 1100, and therefore above the intended liquid level within theseparator 1000, again to prevent water from exiting through the gasoutlet port 1050. The liquid, sand, and debris outlet port 1030 may bepositioned as near to the base of the separator 1000 as is reasonablypractical so that liquid and contaminants cannot collect below theliquid, sand, and debris outlet port 1030. The upper sensor port 1060may be located above the uppermost bridle port 1040 a and the lowersensor port 1062 may be provided below the lowermost bridle port 1040 f,such that the upper and lower limit sensors 1064, 1066 may serve asfailsafes in the event that the liquid level sensor 1400 fails to detectand account for the liquid level being outside the intended range.

It should be noted that an increased vertical length of the bridle 1300may provide additional reaction time for the valve 2000 to release theliquid, sand, and debris from the main body 1010 of the separator 1000.In some embodiments, the length of the bridle 1300 and the probe lengthof the liquid level sensor 1400 may be selected such that the liquidlevel sensor 1400 has a probe length of approximately 80 inches and atargeted liquid level (e.g., a midpoint length of the bridle 1300) ofapproximately 55 inches.

A user interface 4002 may be communicatively coupled to the controller4000 for outputting real time or near-real time data from the controller4000 to a user. The user interface 4002 may take the form of a generalcomputer, a handheld device, a siren, a light bar placed atop theseparator, or any other component designed to output information to auser. The user interface 4002 may output alerts when the liquid level isoutside of a desired range, a malfunction or obstruction in the valve2000 is detected, a detected sand density of the fluid flow indicatesthat the volume of well production should be adjusted, or regularmaintenance is needed.

In some embodiments, as shown in FIG. 8 , an electronically controlledvalve 4055 may be present on a gas line 4022 downstream of the gasoutlet 1050 of the separator 1000. The valve 4055 on the gas line 4022may include any desired type of valve such as, for example, a choke. Thevalve 4055 may be communicatively coupled to the controller 4000, whichcontrols operation of the valve 4055 to control flow of gas through theseparator 1000. The controller 4000 may communicate with one or both ofthe valve 4055 and the valve 2000 to control flow of fluid through theseparator 1000 to maintain the desired liquid level in the separator1000.

In some embodiments, a bypass line 4056 may be fluidly coupled to thegas outlet 1050 to bypass the electronically controlled valve 4055 onthe gas line 4022. A bypass valve 4058 is disposed along the bypass line4056, and the valve 4058 may be selectively opened to allow gas to flowaround the electronically controlled valve 4055. The bypass line 4056and the bypass valve 4058 may be smaller than the gas line 4022 and theelectronically controlled valve 4055, respectively, to handle thesmaller volumetric flow rates of gas exiting the separator during theinitial phases of flowback operations where very little gas is present.The bypass valve 4058 may be manually operated or electronicallyactivated. The bypass line 4056 and valve 4058 may be used to “burp” theseparator 1000 during initial phases of flowback operations, forexample, when extremely large volumes of liquid, sand, and debris areflowing through the separator 1000 without much gas. To maintain theliquid level in the separator 1000 in a desired range during initialphases of flowback, the electronically controlled valve 4055 on the gasline 4022 may be closed. A gas pocket eventually forms at an upperportion of the interior chamber 1100 of the separator 1000, at whichpoint the separator 1000 would need to be “burped” to remove the gaspocket and restore the liquid level. The bypass valve 4058 may be openedand then closed again, thereby removing the gas pocket. The process maybe repeated at regular intervals throughout flowback operations, theseintervals getting shorter and shorter until there is a steady stream ofgas flowing through the separator 1000. Once a steady stream of gas isflowing through the separator 1000, the bypass line 4056 may be closedand the electronically controlled valve 4055 operated after the initialflowback operations.

Having generally described the components of the separator 1000,detailed operation of the separator 1000 will now be described withreference to FIG. 8 . Gas initially enters the separator 1000 from thewellbore W via the inlet port 1020. The inlet port 1020 may be fluidlyconnected to the wellbore W by piping 4100. The gas entering theseparator 1000 may carry with it various contaminants, including water(in both liquid and vapor form) and sand from hydraulic fracturing (i.e.“fracking”). Additionally, the gas may carry debris, such as fragments(e.g., plug pieces) from plugs used during the fracturing process. Onceinside the separator 1000, all media including gas, liquid, sand, anddebris may flow through the pipe 1022 and be deflected downward by thebaffle 1024, in the direction of arrow A. In an alternate embodiment,the pipe 1022 may have multiple openings, as shown in FIG. 7A.

Solid contaminants, such as sand and debris, settle in the bottom of theinterior chamber 1010. Liquid, such as water, fills the interior chamber1010 from the bottom up, establishing a liquid level L. Gas, being lessdense than the liquid flows toward the top of the interior chamber 1010in the direction of arrow B, rises above the liquid to fill the top ofthe interior chamber 1010. A diffuser (e.g., 1054 of FIG. 6 ) in theseparator 1000 may assist the upward movement of gas through theinterior chamber 1010. Once the liquid level L reaches the lowermostbridle port 1040 f, the gas and liquid may flow freely between theinterior chamber 1010 and the bridle 1300 in the direction of arrows Cvia the bridle ports 1040 a-1040 f. The liquid level L thus equalizesbetween the interior chamber 1010 and the bridle 1300.

The gas flows out of the separator 1000 via the gas outlet port 1050 inthe direction of arrow D to piping 4022. The piping 4022 may in turn befluidly connected to downstream components (e.g. a line heater ormolecular dryer).

As the liquid level L rises from continued inflow from the wellbore, thevalve 2000 may be opened to allow liquid, sand, and debris to flow outof the separator 1000 in the direction of arrow E via the outlet port1030. In particular, the liquid, sand, and debris may flow throughpiping 4300 to the holding tank 3000, as shown in FIG. 8 . To preventlarge debris, such as plug fragments, from clogging or damaging thevalve 2000, a strainer 4110 may be provided upstream of the valve 2000to capture such debris.

The valve 2000 may be opened and closed by the controller 4000 based onthe liquid level L as measured by the liquid level sensor 1400. Thecontroller 4000 may receive a signal from the liquid level sensor 1400indicating the vertical position of the liquid level L. If the liquidlevel L is at or above a maximum safe liquid level L_(max), thecontroller 4000 may transmit a signal to the valve 2000 to open thevalve 2000. With the valve 2000 open, liquid, sand, and debris in theinterior chamber 1010 may flow out of the outlet port 1030 in thedirection of arrow E, thereby lowering the liquid level L.

The valve 2000 may remain open until the liquid level L has reached aminimum safe liquid level L_(min). When the liquid level sensor 1400detects that the liquid level L has reached the minimum safe liquidlevel L_(min) the liquid level sensor 1400 may transmit a signal to thecontroller 4000 which in turn may transmit a signal to the valve 2000 toclose the valve 2000. With the valve 2000 closed, the liquid level L mayagain rise to the maximum safe liquid level L_(max), at which time thecontroller 4000 may again open the valve 2000 based on the determinationfrom the liquid level sensor 1400. The valve 2000 may be repeatedlyopened and closed in this manner to maintain the liquid level L betweenthe maximum safe liquid level L_(max) and the minimum safe liquid levelL_(min) as gas is extracted from the wellbore. In some embodiments, thevalve 4055 on the gas line 4022 may be similarly opened and closed tomaintain the liquid level L between the maximum safe liquid levelL_(max) and the minimum safe liquid level L_(min) as gas is extractedfrom the wellbore. By maintaining the liquid level L in this manner,liquid water is prohibited from flowing out of the gas outlet port 1050and gas is prevented from flowing out of the outlet port 1030.

As shown in FIG. 8 , the maximum safe liquid level L_(max) maycorrespond to the position of the uppermost bridle port 1040 a, and theminimum safe liquid level L_(min) may correspond to the position of thelowermost bridle port 1040 d. However, it is to be understood that themaximum safe liquid level L_(max) and the minimum safe liquid levelL_(min) need not correspond to the positions of the bridle port thirdform the top 1040 c and the lowermost bridle port 1040 f, but couldrather correspond to any locations at which liquid may be present in thebridle 1300. With continued reference to FIG. 8 , the piping 4100leading from the wellbore to the separator 1000 may include a shutoffvalve 4120, which may be manually or automatically closed to halt flowinto the separator 1000. In some embodiments, the shutoff valve 4120 maybe controlled by the controller 4000 in response to measurements takenby the liquid level sensor 1400, the upper and lower limit sensors 1062,1066, the density sensors 4052, 4054, or a combination of all of thesensors. The controller 4000 may receive signals from the limit sensors1064, 1066, and based on those signals, transmit a signal to actuate theshutoff valve 4120. If, based on a signal received from the upper limitsensor 1064, the controller 4000 determines that the liquid level withinthe interior chamber 1010 is above a predetermined maximum, thecontroller 4000 may transmit a signal to close the shutoff valve 4120.By closing the shutoff valve 4120, flow into and out of the separator1000 is halted, thereby preventing liquid from advancing downstream.

Similarly, the controller 4000 may transmit a signal to close theshutoff valve 4120 if the controller 4000 determines that the liquidlevel within the interior chamber 1010 is below a predetermined minimum,based on a signal received from the lower limit sensor 1066. By closingthe shutoff valve 4120, flow into and out of the separator 1000 ishalted, thereby preventing the separator 1000 from running dry and thepressure from getting too high in the holding tank 3000.

The controller 4000 may also transmit a signal to open, close, ormodulate the shutoff valve 4120 to control the flow of fluid into theseparator 1000 from the well based on a determination of the sandconcentration of the fluid flowing through the separator 1000. Asdiscussed above, the controller 4000 may determine the real timeconcentration of sand flowing through the separator 1000 based onmeasurements taken via the density sensors 4052, 4054. The controller4000 could also be programmed to close the valve 4120 if fluid flow isdetected through valve 2000 by sensor 4054 when valve 2000 is in theclosed position.

In some embodiments, the controller 4000 may utilizeproportional—integral— derivative (PID) logic to continuously and/orrepeatedly receive measurement signals from the liquid level sensor1400, and subsequently actuate the valve 2000 and/or the valve 4055 tomaintain the desired liquid level L in the manner described herein.Similarly, the controller 4000 may utilizeproportional—integral—derivative (PID) logic to continuously and/orrepeatedly receive measurement signals from the upper and lower limitsensors 1064, 1066 and/or the density sensors 4052, 4054 andsubsequently actuate the shutoff valve 4120 in response to fluid levelin the interior chamber 1010 and/or the concentration of sand flowingthrough the separator 1000.

As described herein, the controller 4000 may be in communication withthe liquid level sensor 1400, the valve 2000, the valve 4055, the upperand lower limit sensors 1064, 1066, the density sensors 4052, 4054, theshutoff valve 4120, and the valve position sensor 4050. The controller4000 may include at least one processor programmed or configured toexecute instructions stored on computer-readable media. The controller400 may communicate with the liquid level sensor 1400, the valve 2000,the valve 4055, the upper and lower limit sensors 1064, 1066, thedensity sensors 4052, 4054, the shutoff valve 4120, and the valveposition sensor 4050 by any suitable wired or wireless communicationprotocols and interfaces such as 4-20 milliamp HART signal, Ethernet,fiber optics, coaxial, infrared, radio frequency (RF), a universalserial bus (USB), Wi-Fi®, cellular network, and/or the like. Thecontroller 4000 may be in communication with a user interface 4002 toprovide real-time feedback to the electronic controller and/or to anoperator of the liquid level L within the interior chamber 1010, and/orreal-time feedback that the separator 1000 and its associated componentsare operating properly.

Referring now to FIGS. 13 and 14 , the separator 1000 may be used as acomponent of a gas processing facility 5000 including the separator 1000and a line heater and choke assembly 5100. FIG. 13 shows two separators1000 feeding into a single line heater and choke assembly 5100, althougha single separator 1000 may also be used. The two separators 1000 may beused to produce gas from two different wells simultaneously. Asillustrated, the two separators 1000 may be positioned side by side andconnected to the same skid 1090 of downstream equipment (e.g., a singleline heater and choke assembly 5100 for both separators 1000), therebysaving space. The line heater and choke assembly 5100 includes a lineheater 5200 and a choke 5300. Gas, water, and contaminants flow in theseparator 1000 from the wellbore W, where the water and contaminants areseparated from the gas as described herein. Gas flowing out of theseparator 1000 via the gas outlet port 1050 and the piping 4022 flowsinto the line heater 5200. The line heater 5200 may include, forexample, one or more coils disposed in a heated glycol bath. Gas fromthe separator 1000 flows through the coils until the gas reaches adesired temperature and/or pressure. The gas exiting the line heater5200 then flows through the choke 5300, which drops the pressure of thegas to a desired line pressure, for example 1,400 psi.

Referring now to FIG. 15 , a flow diagram of a process 6000 for gasproduction from a well is shown as substantially described herein. Theprocess 6000 may be a process for producing a pressurized natural gasstream from a fluid being produced from a wellbore. The process 6000 maybe fully or partially automated by the controller 4000. At step 602, thegas flow to the separator 1000 from the wellbore W may be initiated.This may be achieved, for example, by opening the shutoff valve 4120 viathe controller 4000. Alternatively, the shutoff valve 4120 may bemanually opened. The fluid may be directed into the separator 1000 at apressure substantially equal to the pressure of the fluid being producedfrom the wellbore.

At step 604, the liquid level L within the interior chamber 1010 may bedetermined. In particular, the liquid level sensor 1400 may transmit asignal indicating the liquid level L to the controller 4000. The liquidlevel sensor 1400 may provide real-time feedback of the liquid level Lto the controller 4000.

The process 6000 may further include controlling the liquid level L inthe separator 1000 between two predetermined set points (e.g., L_(max)and L_(min)) by regulating the flow of the liquid, sand, and other soliddebris out of a lower portion of the separator 1000. For example, atstep 606, the electronically controlled valve 2000 may be opened orclosed, or modulated, in response to the determination of the liquidlevel L. In particular, the controller 4000 may transmit a signal toopen the valve 2000 if the liquid level L is at or above the maximumsafe liquid level L_(max), and the controller 4000 may transmit a signalto close the valve 2000 if the liquid level L is at or below the minimumsafe liquid level L_(min). Modulation of the valve 2000 also allowsaccumulated sand and debris to exit the separator 1000, such that manualcleaning is not required. The process 6000 may further include directingthe gas (substantially cleaned of liquid, sand, and debris) out of theseparator 1000 at a pressure substantially equal to the pressure of thewellbore.

At step 608, the liquid level L within the internal chamber 1010 of theseparator 1000 may be verified or confirmed to be within a proper rangeutilizing the upper limit sensor 1064 and/or the lower limit sensor 1066in case of a malfunction of the liquid level sensor 1400. In particular,the upper limit sensor 1064 and/or the lower limit sensor 1066 maytransmit a signal to the controller 4000 indicative of the presence ofliquid at the upper sensor port 1060 and the lower sensor port 1062.

At step 610, the shutoff valve 4120 may be closed in response todetermining that the liquid level L in the interior chamber 1010 isoutside of the proper range. In particular, the controller 4000 maytransmit a signal to close the shutoff valve 4120 if the liquid level Lis above the upper limit sensor 1064 or if the liquid level L is belowthe lower limit sensor 1066. Steps 604, 606, 608, and 610 may berepeated periodically, continuously, and/or at predetermined timeintervals during the service life of the well.

In some embodiments, the controller 4000 may require a “handshake”verification between the liquid level sensor 1400 and the upper andlower limit sensors 1064, 1066 to actuate the valve 2000. That is, thecontroller 4000 may require that the liquid level determined by theliquid lever sensor 1400 matches the liquid level determined by theupper and/or lower limit sensors 1064, 1066 prior to actuating the valve2000. The controller 4000 may use this “handshake” to diagnose a faultin the liquid level sensor 1400, the upper limit sensor 1064, and/or thelower limit sensor 1066. The controller 4000 may use this manner offault detection to ensure that the separator 1000 is operating properlyand may provide feedback to an operator that the separator 1000 is (oris not) operating properly. With this precision control, electronic,real-time feedback provided to the operator to ensure that the separator1000 is operating properly, and redundant protections to ensure that theseparator 1000 does not overflow or empty, it is virtually impossiblefor gas to be lost to tanks on location.

The system and process of the present disclosure can allow for highergas and liquid flow rates than the existing sand separator and GPUlegacy configuration. Because fluid separation is occurring downstreamof the pressure cut in the GPU within the legacy configuration, and theassociated gas expansion and system velocities increase, turbulence inthe GPU is amplified. As such, the legacy system can be limited to amaximum of 60 barrels/hour. The separator 1000 of the present disclosureallows for liquid separation to occur at significantly higher pressuresthan in the existing system, which means that the liquid separation ofthe present disclosure occurs at lower fluid velocity and, consequently,less turbulent flow. For example, the separator 1000 may allow forliquid handling capacities in excess of 200 barrels/hour using aseparator 1000 with a working volume of only 8 barrels. This advantagemay eliminate the need to employ third party flowback services, whichrequire process flowrates on the order of 120 barrels/hour.Additionally, manpower is greatly reduced utilizing the technologydescribed as almost all aspects of the operation are automated. Theoperation can be considered “eFlowback”.

Due to the safety concerns associated with gas production, any of thecomponents of the separator 1000 described herein may be provided induplicate and/or may include redundant systems in order to ensure safeoperation of the separator 1000. Additionally, two separators 1000, 1001may be built onto one skid and used in series, the first acting as aprimary separator and the second as a polishing or back up vessel in theevent fluid is carried over from the primary vessel. This arrangement isillustrated in FIG. 21 . This configuration is particularly advantageousin systems that use a molecular dryer, as it is critical that freeliquid should never make contact with the molecular dryer and molecularsieve, desiccant or other material it contains. Alternatively, inoperations where some free liquid carryover is not problematic theseparator 1000 can be used in parallel, for example as shown in FIG. 17where the separator 1000 is working in tandem with conventionalproduction equipment shown in FIG. 1 . In this example, the skid mayhave two separators 1000 in parallel that can be used to flowback twowells, as shown in FIG. 17A. Ultimately, in this configuration, thesystem can serve in two unique applications.

Having generally described the separator 1000 and its operation, variousapplications in which the separator 1000 may be used will now bedescribed with reference to FIGS. 17-21 . However, as those of ordinaryskill in the art will appreciate, the separator 1000 may also be used inconjunction with a conventional GPU 20 (as shown in FIG. 1 ). FIG. 17illustrates a gas production facility 700 including the separator 1000being used to perform a flowback operation for a well. The well isdesignated in FIG. 17 by a tree 702, which is located at the wellhead.The tree 702 may be a standard Christmas tree 702 located above a welland comprising multiple valves and bores through which fluid may bedirected from the well. The tree 702 is configured to output fluidproduced from a wellbore. The fluid produced from the wellbore mayinclude gas, liquid, sand, and debris.

During flowback operations, liquid, sand, and debris may make up asignificant proportion of the fluid being produced from the wellbore.Flowback operations may last for 5 days, 1 week, 2 weeks, or up to amonth or more. Permanent production equipment that is used to processgas output from the well is not designed to handle the large amounts ofliquid, sand, and debris that is removed from the well during flowbackoperations. The separator 1000 described at length above may be used toclean the liquid, sand, and debris from the well fluid during flowbackoperations so that the same gas processing equipment (e.g., gasprocessing unit 704) may be used to process the gas during flowbackoperations and during the longer production phase after flowbackoperations. The gas processing unit 704 may include at least a choke forreducing a pressure of the gas or fluid flowing therethrough. Theillustrated arrangement of the separator 1000 and gas processing unit704 used to provide flowback operations has a much smaller footprintthan conventional third-party flowback spreads.

The separator 1000 may be connected to the tree 702 and gas productionunit 704 via a series of flow paths, each flow path taking the form ofrigid or flexible piping. The gas production facility 700 may include,for example, a first flow path 706 connecting a first outlet 708 of thetree 702 to the inlet 1020 of the separator 1000. The inlet 1020delivers the fluid into the separator 1000 at a first pressure. Thefluid may comprise liquid, gas, sand, and debris. As illustrated anddescribed in detail above, the separator 1000 includes the inlet 1020and a gas outlet 1050 through which gas (separated from the liquid,sand, and debris) is delivered from the separator 1000. The gasproduction facility 700 may also include a second flow path 710connecting a second outlet 712 of the tree 702 to the gas productionunit 704. Fluid may flow from the well directly to the gas productionunit 704 via the second flow path 710 when a valve at the second outlet712 is open. The gas production facility 700 may further include a thirdflow path 714 connecting the gas outlet 1050 of the separator to the gasproduction unit 704 or, more particularly, to the second flow path 710leading to the gas production unit 704. As illustrated, a valve 716 maybe disposed along the third flow path 714 for selectively opening andclosing the third flow path 714. As illustrated in FIGS. 17 and 17A, aby-pass valving system (e.g., including an electronically controlledvalve 4055, bypass line 4056, bypass valve 4058, and/or gas measurementdevice 1057 as discussed with reference to FIG. 8 ) may be disposedalong the third flow path 714 in addition to the valve 716. The by-passvalving system may enable the control of gas flowing from the separator1000 throughout flowback operations (e.g., when it may be desirable to“burp” the vessel of the separator 1000) and after flowback operationswhen a substantially flow of gas has been established. In someembodiments, the valve 716 may not be present such that the by-passvalving system provides all control of flow through the third flow path714.

During flowback operations, a valve at the second outlet 712 of the tree702 may be closed while a valve at the first outlet 708 of the tree 702may be opened. That way, fluid containing large amounts of liquid, sand,and debris is directed to the separator 1000 through the first flow path706. The separator 1000 may remove the liquid, sand, and debris throughthe outlet 1030 by controlling the valve 2000 according to the methoddescribed above. The gas separated from the liquid, sand, and debris isdelivered out of the separator 1000 through the outlet 1050 and throughthe third flow path 714 and the second flow path 710 to the gasproduction unit 704 (e.g., following arrows 718). The liquid, sand, anddebris separated from the gas may pass through a junk catcher or othertype of filter 4110 so as not to clog the valve 2000. Downstream of thevalve 2000, the liquid, sand, and debris may be manifolded to an outletof the gas production unit 704 through which liquid, sand, and/or debrismay also be directed out of the gas production unit 704.

After flowback operations are completed or once a gas volume suitablefor permanent equipment is reached (e.g., once the well is producinglargely gas), the valve at the second outlet 712 of the tree 702 may beopened and the valve at the first outlet 708 closed, thereby allowingthe fluid to flow from the well directly to the gas production unit 704instead of the separator 1000. Thus, the separator 1000 may alone or incombination with a conventional system as shown in FIG. 1 replace aconventional flowback spread for removing large amounts of liquid, sand,and debris.

Referring to FIGS. 18-21 , the separator 1000 according to the presentdisclosure may be used not only for gas production to a pipeline, but togenerate other products or energy using substantially less equipment onlocation and at lower cost than conventional methods. This is becausethe disclosed separator 1000 is able to output a highly pressurized andsubstantially clean gas stream. Removing all free liquid from the gasstream at approximately wellhead pressure (prior to any pressure cut)enables new and improved uses of wellhead energy. For example, thewellhead energy may be used for one or more of power generation, assubsequently hydrogen, oxygen, a naturally formed compressed natural gas(CNG) production, and liquefied natural gas (LNG) production, and otheruseful products

FIG. 18 illustrates a system 800 that may utilize the pressurized gasstream to simultaneously power one or more processes in addition to, orin lieu of, supplying gas to a pipeline 810. Each of the componentsillustrated in FIG. 18 may be an individual piece of mobile equipmentbrought to a well location. The separator 1000, as illustrated, maygenerally include the inlet 1020, the liquid, sand, and debris outlet1030, and the gas outlet 1050. The separator 1000 may include the samecomponents and operate as described above with reference to any of FIGS.2-12 and 16 . The inlet 1020 may deliver fluid being produced from awellbore into the separator 1000 at a first pressure, and the fluid maycomprise liquid, gas, sand, and debris. The gas outlet 1050 isconfigured for delivering gas separated from the liquid, sand, anddebris out of the separator 1000 at a second pressure. The secondpressure may be substantially equivalent to the first pressure in someembodiments. In other embodiments, the second pressure may be differentthan the first pressure. The outlet 1050 may be connected to aparticulate filter 802, which may be connected to a molecular dryer 804.As such, the outlet 1050 is connected to the molecular dryer 804. Theoutlet 1050 may also or alternatively connected to a gas processing unit704.

The molecular dryer 804 is a molecular vapor dryer, which removes watervapor from the gas stream. As those of ordinary skill in the art willappreciate, the molecular dryer 804 may be a molecular sieve, amembrane, or any other device or process capable of removing all or mostof the water vapor from the gas stream output from the outlet 1050, suchthat the remaining gas stream could meet the parts per million (PPM)requirements needed for powering certain downstream equipment. Asillustrated, the molecular dryer 804 has at least one outlet throughwhich the gas substantially removed of water vapor is directed out ofthe molecular dryer 804. As those of ordinary skill in the art willappreciate, the molecular dryer could be any device that removes watervapor from gas.

After passing through the molecular dryer 804, the gas stream may besplit and/or directed downstream to perform one or more processes. Inthe illustrated embodiment, the gas stream is split after the moleculardryer 804. The different portions of the gas stream are then deliveredto a CNG filling station 806, delivered to a pipeline 810, liquefied toproduce LNG 818, used to generated electricity 812, and the power wouldthen be used to generate hydrogen 814. As those of ordinary skill in theart will appreciate, CNG filling station 806 may be stationary storagetanks or trucks. The stream of gas directed into the CNG filling stationis compressed natural gas, which the industry defines as CNG. Becausethe CNG produced through this process does not use external orhuman-made compression, it will be referred to herein as “naturallycompressed natural gas.” Although all these processes are illustrated inFIG. 18 , it should be understood that fewer or more processes may beperformed using the pressurized gas stream output from the moleculardryer 804. The one or more gas streams may be output from the moleculardryer 804 at a third pressure, which may be substantially the same ordifferent than one or both of the first and second pressures describedabove.

As illustrated, the CNG filling station 806 may be connected to anoutlet of the molecular dryer 804 such that a first gas stream outputfrom the molecular dryer may be directed to the CNG filling station 806.In some embodiments, a pressure control valve 820 is disposed betweenthe CNG filling station and the molecular dryer for reducing orotherwise controlling the pressure of the gas being directed out of themolecular dryer from the third pressure to a lower pressure. Forexample, the third pressure may be approximately 5,000 psi, while thefourth pressure may be approximately 3,600 psi. That way, the gas streamis brought down to a desired pressure needed for filling CNG tanks. Inother embodiments, the pressure control valve 820 may not be present.

Modern CNG is typically compressed from pipeline pressure as low as 50psi up to pressures of approximately 5,000 psi. By precisely removingall free liquid from the well at wellbore pressures via the separator1000 and molecular dryer 804, CNG may be generated with no compression.There is significant reduction of capital, operating costs and emissionsassociated with eliminating the compression element of producing CNG andallowing the wellbore pressure to provide the pressure necessary to filltanks or high-pressure pipelines.

As illustrated in FIG. 18 , the system 800 may comprise a turbo expander808 connected to an outlet of the molecular dryer 804. An exemplaryturbo expander converts changes in pressure into rotational/mechanicalenergy that can be used for compression, power generation and the like.(As used herein, a “turbo expander” is defined as a device that createsmechanical energy from a pressure differential). It may also producecooling via the Jules Thompson Effect. It may include and be coupledwith or connected to a gas compressor, an electric generator or anyother device, system or process requiring the mechanical energy and/orrotational energy it produces. As those of ordinary skill in the artwill appreciate, wherever it is disclosed to use a turbo expander, apiston expander, reciprocating expander, centrifugal compressor or apositive displacement expander may be used in its place. An exemplarycombination turbo expander compressor might include a Compander™ brandturbo expander/compressor. The turbo expander 808 may be powered by thegas directed out of the molecular dryer and used to generate electricity(812) and subsequently hydrogen (814) through electrolysis. The turboexpander 808 may include an inlet for receiving the pressurized cleangas flow from the molecular dryer 804 and one or more outlets throughwhich gas is output from the turbo expander at a lower pressure. In someembodiments, the system 800 may include a pressure control valve 822disposed between the outlet of the molecular dryer 804 and the turboexpander 808 for reducing a pressure of the gas being directed out ofthe molecular dryer from one pressure to a lower pressure. For example,the pressure control valve 822 may reduce the pressure fromapproximately 5,000 psi to approximately 2,500 psi or the technicallimits of existing turbo expander technology. Existing Utica wells cangenerate the equivalent of over 10,000 horsepower of energy. This maybring the gas stream down to a desired pressure so that the gas streamis output from the turbo expander at an appropriate pipeline pressure(e.g., 1,000 psi). It should be noted that the pressures listed here aremerely examples and other embodiments may include the gas stream atdifferent pressures.

The turbo expander 808 may function as a generator, converting thepressure drop of the gas moving through the turbo expander 808 intoelectricity (812). The pressurized gas flow is able to be used in aturbo expander due to the fact that all liquid has been removed from thegas stream (e.g., via the separator 1000 and the molecular dryer 804)without a significant pressure drop. In some embodiments, the generatedelectricity (812) may be used to power on-site equipment or distributedto the local power grid. In some embodiments, the electricity may beused to generate emissions free hydrogen through electrolysis (814).Using the separator 1000, the molecular dryer 804, and the turboexpander 808, the system 800 may be able to generate electricity at thewell with zero emissions.

As illustrated, the system 800 may include a gas pipeline 810 connectedto the outlet of the turbo expander 808. In other embodiments, thesystem 800 may include a gas pipeline 810 connected to an outlet of themolecular dryer 804. The gas pipeline 810 may deliver natural gas to anatural gas pipeline. As will be understood by one of skill in the art,the gas pipeline 810 may deliver natural gas at a pipeline pressure(e.g., 1,000 psi) that is lower than the pressure at which gas is outputfrom the molecular dryer 804 (e.g., 5,000 psi). As such, the pressure ofthe gas is reduced prior to supplying the gas to the pipeline 810. Thispipeline pressure may be a pressure at which the natural gas gridsupplies gas to communities. In FIG. 18 , for example, the turboexpander 808 is connected between the gas pipeline 810 and the moleculardryer 804 for reducing the pressure of the gas being directed throughthe turbo expander 808 to a lower pressure that is substantially equalto the desired pipeline pressure and generating electricity andsubsequently hydrogen in the process. The pressure control valve 822 mayalso reduce the pressure exiting the molecular dryer. In someembodiments, although not explicitly depicted, the turbo expander may beomitted, replaced with a JT (Joule Thomson) valve or the pipeline 810may not be connected to the turbo expander 808. In such instances, apressure control valve 822 may be connected between the gas pipeline 810and the molecular dryer 804, and the pressure control valve 822 mayreduce the pressure of gas being directed out of the molecular dryer 804to a pressure that is substantially equal to the desired pipelinepressure.

The disclosed system 800 may provide gas to the pipeline 810 withreduced or no emissions. Because of the use of the disclosed separator1000 in combination with the molecular dryer 804, the gas being providedto the pipeline 810 and/or other downstream components of the system 800is substantially free of water vapor and contaminants. When the pressureof the gas is reduced, by a pressure control valve 822, JT valve, turboexpander 808, or all three, there is no possibility of water vapor inthe gas stream freezing and damaging equipment. Therefore, no burners orother heat sources are needed to prevent water from freezing in the gasstream. As such, the pressure reduction needed to bring the gas streamto pipeline pressure can be accomplished without the emissions releasedby conventional burners.

The separator 1000, molecular dryer 804, and turbo expander 808 may alsoenable the generation of LNG 818 without electricity or outside energy.LNG 818 is natural gas that has been cryogenically cooled to −260° F. toliquify LNG 818 and is typically stored at 5 PSIG or less. Asillustrated, the system 800 may include a cold box 816 connected to theturbo expander 808. In other embodiments, although not explicitlydepicted, the system 800 may include a cold box 816 connected to anoutlet of the molecular dryer 804. (The cold box 816 is configured tocapture the cold gas exiting the turbo expander 808 (or molecular dryer804) so as to produce LNG 818 at lower pressure than the incoming gas.As used herein “cold box” is defined as one or more components of a heatexchange equipment, valves, controllers, heat retention and all otherassociated devices and processes to support the liquification process)In the embodiment of FIG. 18 , the turbo expander 808 may producesupercooled gas in additional to electricity 812 and subsequentlyhydrogen 814. The turbo expander 808 may be connected to refrigerationcompression. The cold box 816 may be connected to refrigerated fluid orgas outlet to receive the cooling fluid 824 for cryogenically coolingthe gas exiting the turbo expander 808 (or molecular dryer 804).

The disclosed system 800, in which pressurized gas is provided via theseparator 1000 and molecular dryer 804, may aid in lowering the capitaland operating expense of a liquefaction facility for generating LNG,since no outside electricity or energy is needed to reduce the gaspressure or operate the cold box 816. The disclosed system 800 mayfurther reduce the environmental and emissions footprint needed forproducing LNG. Depending on gas composition, additional gas conditioningdownstream of the molecular dryer maybe be required for LNG production,such as carbon dioxide and heavy hydrocarbon (e.g., Butane, Pentane,etc.) removal. Accordingly, the embodiments shown in FIGS. 18-21optionally include a conditioner 805 immediately downstream of themolecular dryer 804.

FIG. 19 depicts another system 900 that may utilize the pressurized gasstream to simultaneously power one or more processes in addition to, orin lieu of, supplying gas to a pipeline 810. The system 900 shown inFIG. 19 is similar to the system 800 shown in FIG. 18 , except that thepressure control valves 820 and 822 have been replaced with anotherturbo expander 826. This second turbo expander 826 is disposed betweenthe outlet of the molecular dryer 804 and the turbo expander 808. Theturbo expander 826 may reduce the pressure of the gas being directed outof the molecular dryer 804, and the turbo expander 808 may then reducethe pressure of the gas being directed out of the turbo expander 826. Ingeneral, any pressure drop that is needed to provide gas to a downstreamprocess may be accomplished using a turbo expander 808, 826 asillustrated. This may help to further conserve energy by converting allpressure drops into work to generate electricity 812, 828, hydrogen viahydrolysis 814, 830, and/or cooling fluid 824, 832 to supply a cold box816. Any desired number of turbo expanders may be connected in seriesbetween the molecular dryer 804 and the downstream component(s) needinga reduced pressure flow of gas.

As shown in FIG. 19 , the system 900 may include a compressed naturalgas filling station 806 connected to an outlet of the closest turboexpander 826 to the molecular dryer 804. The turbo expander 826connected between the compressed natural gas filling station 806 and themolecular dryer 804 may reduce the pressure of gas being directed out ofthe molecular dryer to a lower pressure that can be used to fill CNGtanks (806). The CNG filling station 806 may need gas provided at apressure higher than some other downstream processes (e.g., LNGgeneration or supplying the pipeline), which is why it receives gasoutput after the first pressure drop via turbo expander 826.

FIG. 20 depicts yet another system 2001 that may utilize the pressurizedgas stream to simultaneously power one or more processes in addition to,or in lieu of, supplying gas to a pipeline 810. The system 2001 shown inFIG. 20 is similar to the system 800 shown in FIG. 19 , except that anauxiliary chiller 852 is connected to the cold box 816 to further chillhydrogen 848 and/or oxygen 850 being produced through the electrolysisprocess 846 to produce liquid hydrogen (H₂) and liquid oxygen (O₂). Asthose of ordinary skill in the art will appreciate, because oxygenliquifies at a higher temperature than hydrogen, each would need its ownunique flow path from the auxiliary chiller 852 or alternativelyseparate heat exchange/auxiliary chilling devices. Power 842 output fromthe turbo expanders 808 and 826 through the power generation and coolingsteps 840 is used to separate hydrogen 848 from oxygen 850 in anelectrolysis process 846. The hydrogen 848 and oxygen 850 are then fedinto the cold box 816 (which is made cold as noted above with referenceto FIGS. 18 and 19 through the cooling fluid exiting the turbo expanders808 and 826 as the gas passes through these devices). The cold box 816can produce LNG 818 as described in FIGS. 18 and 19 and also liquidoxygen 854 and liquid hydrogen 856 through the aid of auxiliary chiller852, which could be powered by a turbo expander via electricity ormechanically through compression. The auxiliary chiller 852 furthercools these gases to the point that they undergo a phase change andbecome liquid. The liquid oxygen 854 is cooled to approximately −297° F.and the liquid hydrogen 856 is cooled to approximately −423° F. Theoxygen 850 is stored at approximately 350 psi or lower as it passesthrough the auxiliary chiller 852 and the hydrogen 848 is stored atapproximately 45 psi as it passes through the auxiliary chiller 852.

FIG. 20 illustrates that another turbo expander 834 can be connecteddownstream of turbo expander 808 to generate additional power andcooling by harvesting the energy generated by further reducing the gaspressure to get it to a pressure which would allow it to be transportedby gas pipeline 810. In the embodiments shown in, and described inreference to, FIGS. 18-21 , a compressor may optionally be connected to,and powered by, the turbo expanders within the system, either throughdirect connection compression or power by the electricity generatedwithin the process. These compressors can be utilized for facilitatingthe compression of hydrogen, oxygen, natural gas, refrigerant gases orother gases into a truck, a separate pipeline, the cold box or forblending with natural gas in pipeline 810.

The embodiment in FIG. 20 further proposes to harvest additional energyfrom the high-pressure liquid exiting from the bottom of the separator1000. First, the liquid, sand and debris existing the separator 1000through outlet port 1030 must have the solids material removed from it.This is done by passing the fluid mixture through a mechanism forremoving solids 860. As those of ordinary skill in the art willrecognize the mechanism for removing solids from the liquid may includea strainer or junk catcher or similar device. Once the sand and othersolid debris is removed the resultant high-pressure liquid can be passedthrough hydroelectric turbine 870, which in turn can generateelectricity 812 for local power consumption (e.g., in powering thevarious equipment used in the above mentioned processes) and/or fordelivery to the power grid. As will be appreciated by those of ordinaryskill in the art multiple hydroelectric turbines 870 may be connected inseries to harvest as much energy as possible from the high-pressureliquid.

The embodiment of FIG. 20 may further comprise a compressor 880 fluidlyconnected to the electrolysis device 846 into which the hydrogen 848 maybe fed to allow the hydrogen to be compressed and subsequently deliveredto customers, for example, via a truck 882 or the gas pipeline 810.Alternatively, the hydrogen 848 can be delivered via a dedicatedhydrogen pipeline 890. As those of ordinary skill in the art willappreciate compressed hydrogen can be blended with natural gas as burnedfor power generation as newer gas turbine engines are capable of burninga blend of hydrogen and natural gas. In one exemplary embodiment, thefuel for such a turbine contains 15% hydrogen. Similarly, the truck 882can transport the hydrogen gas for subsequent blending or other use at aremote location.

FIG. 21 illustrates the system 2001 of FIG. 20 having two separators1000 and 1001 coupled in series to provide the pressurized gas flow tothe molecular dryer 804 and other downstream components, as referencedabove.

The systems 800, 900 and 2001 of FIGS. 18-21 , are merely examples ofdifferent arrangements of processes that may be combined to utilize thepressurized gas output from separator 1000. Other arrangements may bepossible in other embodiments. Since free and abundant energy isavailable through the pressurized flow of gas from the separator 1000,there is no need to design the entire system around one product (e.g.,CNG, LNG, electricity, or hydrogen). Since CNG and LNG can be producedwithout compression, all the waste energy from the pressure dropsthrough the system can be harnessed to generate electricity and/or tomake hydrogen.

FIG. 22 depicts yet another system 2200 that may utilize a pressurizedgas stream to simultaneously power one or more processes in addition to,or in lieu of, supplying gas to a pipeline 2212. FIGS. 23 and 24 depictmore detailed embodiments of the system 2200 depicted schematically inFIG. 22 .

The system 2200 illustrated in FIG. 22 may be used within the system(s)illustrated in FIGS. 20 and 21 . For example, the system 2200 (or one ormore components thereof) may be used in place of the cold box 816, turboexpander 834, and/or turbo expander 808 illustrated in FIGS. 20 and 21 .FIG. 22 depicts a conditioner 2202 located upstream of the othercomponents of the system 2200. The term “conditioner” 2202 may refer toany number of pieces of equipment used to condition a pressurized gasstream (such as the filter 802, molecular dryer 804, and/or conditioner805 in FIGS. 20 and 21 ). Any desired number and arrangement ofequipment may be located within or upstream of the conditioner 2202 inFIG. 22 , as long as the conditioner 2202 outputs a pressurized gasflow. The pressurized gas flow may be at a pressure approximately equalto a pressure at which gas is produced from a wellbore. The pressurizedgas flow may be at least 1,500 psig. The pressurized gas flow may besubstantially removed of water vapor. The pressurized gas flow may be astream of gas that was produced from a wellbore and separated fromliquid, sand, and debris at a pressure substantially equal to wellborepressure (e.g., via the separator 1000 described above), therebyharnessing the energy from the wellbore. In other embodiments, thepressurized gas flow may be any other type of high pressure gas feed,such as a transmission pipeline gas feed. In such instances, componentsof the system 2200 may be located at or proximate a pressure letdownstation where the transmission pipeline gas is throttled from a higherpressure to a lower pressure for sending to a distribution pipeline(e.g., the pipeline 2212).

The system 2200 of FIG. 22 includes a heat exchanger 2204, which mayalso be referred to as a “cold box”. The heat exchanger 2204 may includea number of passages therein through which the pressurized gas streamoutput and other gas/vapor streams flow. The heat exchanger may enablecooling/heating of certain streams flowing therethrough. The heatexchanger 2204 may include a first inlet 2205 fluidly connected to theconditioner 2202 and configured to receive a first pressurized gasstream. The heat exchanger 2204 may also include a first outlet 2207connected to the first inlet 2205. The heat exchanger 2204 may cool thefirst pressurized gas stream moving through the heat exchanger from thefirst inlet 2205 to the first outlet 2207. As such, the first outlet2207 may output a chilled gas stream produced by the heat exchanger 2204cooling the first pressurized gas stream.

The system 2200 also includes a turbo expander 2206 coupled to the firstoutlet 2207 of the heat exchanger 2204. The turbo expander 2206 may bereferred to as an “LNG turbo expander”, as it is used to produce LNG2208. The turbo expander 2206 is connected to the first outlet 2207 ofthe heat exchanger 2204 for receiving the chilled gas stream produced bythe heat exchanger 2204 and then producing a partially liquified gasstream. The partially liquified gas stream may comprise LNG 2208 and(non-liquified) vapors. During operation, the turbo expander 2206reduces the pressure of the cryogenically cooled gas (e.g., expandingthe chilled gas stream output from the outlet 2207 of the heat exchanger2204), thereby cooling the gas further and partially condensing it intoLNG 2208. The turbo expander 2206 may chill the cold, high-pressure gasstream down to a point where approximately 38% of the gas stream isliquified. In some embodiments, the turbo expander 2206 may reduce thepressure of the chilled gas stream to 10 psig or less, more particularly7.5 psig or less, or more particularly approximately 5 psig.

As the turbo expander 2206 only partially liquifies the gas stream, thesystem 2200 may further include at least one separator 2214 connected tothe turbo expander 2206. The partially liquified gas stream is fed intothe separator(s) 2214 and the separator(s) 2214 separate the vapors fromthe LNG 2208. Thus, the system allows for production and isolation ofLNG 2208, which can be stored in tanks for transportation away from thewellsite or used as fuel on location. The separator(s) 2214 may includeone or more vessels for separating cryogenically cooled vapors from LNGat various pressures.

The vapors removed from the LNG via the separator(s) 2214 may bedirected into the heat exchanger 2204 for use as additional coolingfluid. To that end, the heat exchanger 2204 may include at least onevapor inlet (e.g., 2215) connected to the separator(s) 2214 forreceiving vapors removed by the separator(s) 2214. The heat exchanger2204 may then cool the first pressurized gas stream via heat transferbetween the first pressurized gas stream and the vapors. In particular,the first pressurized gas stream entering via inlet 2205 and exiting viaoutlet 2207 is cooled, while the pre-chilled vapors entering viainlet(s) 2215 are heated in the heat exchanger 2204.

The heat exchanger 2204 may also include at least one vapor outlet(e.g., 2217) used to output the vapors from the heat exchanger 2204. Thesystem 2200 may include a vapor recovery unit (VRU) designed to use amajority or all of the vapors output from the separators 2214 so thatthe vapors do not have to be burned. The VRU, for example, may include acompressor used to raise the pressure of the cryogenically cooled vaporsto a pressure greater than or equal to pipeline pressure. The VRUessentially boosts the leftover vapors to pipeline pressure so as toavoid releasing emissions by flaring the vapors. As illustrated, thesystem 2200 may include at least one compressor 2216 connected betweenthe at least one vapor outlet 2217 of the heat exchanger 2204 and thepipeline 2212. The at least one compressor 2216 may compress the vaporsoutput from the heat exchanger to a pressure suitable for the pipeline2212 and output a compressed gas toward the pipeline 2212 at apipeline-suitable pressure.

The turbo expander 2206 may be coupled to the at least one compressor2216, as illustrated, to supply power 2218 generated by the turboexpander 2206 to the at least one compressor 2216. The power generatedby the turbo expander 2206 may be supplied to the compressor(s) 2216 foroperating the compressor(s) 2216. As an example, the turbo expander 2206may be mechanically coupled to the compressor(s) 2216, e.g., via one ormore shafts and/or a set of gears. Thus, the turbo expander 2206 maysupply mechanical power to drive the compressor(s) 2216. In anotherexample, the turbo expander 2206 may be electrically coupled to thecompressor(s) 2216 via a generator driven by the shaft of the turboexpander 2206, which produces electricity, and one or more motors thatuse the generated electricity to turn the compressor(s) 2206. The turboexpander 2206 may generate electricity via mechanisms discussed atlength above with reference to FIGS. 18-21 . In yet another example, theturbo expander 2206 may be mechanically coupled to the compressor(s)2216 and also coupled to a generator, so that any additional powerproduced by the turbo expander 2206 over what is needed to drive thecompressor(s) 2216 may be converted to electricity (which may be used topower other processes on location, supplied to a grid, etc.).

As illustrated in FIGS. 22-24 , an initial gas stream 2302 (e.g., gasstream output from the conditioner 2202 of FIG. 22 ) may be split into afirst pressurized gas stream 2306 and a second pressurized gas stream2308. The system 2200 may include a feed splitter 2304 upstream of theheat exchanger 2204 for splitting the initial gas stream 2302 into thesetwo component streams. The feed splitter 2304 may take any desired formapparent to a person of ordinary skill in the art. For example, the feedsplitter 2304 may be a simple T-shaped or Y-shaped joint and/or mayinclude one or more valves for controlling a relative amount of thefirst and second pressurized gas streams.

The first pressurized gas stream 2306 may be fed to the first inlet 2205of the heat exchanger 2204, while the second pressurized gas stream 2308may be fed to a second turbo expander 2210. The second turbo expander2210 may be referred to as a “gas line turbo expander” as it is used toprovide gas to the pipeline 2212. The second turbo expander 2210 may beconnected between the feed splitter 2304 and a second inlet 2220 of theheat exchanger 2204. The second turbo expander 2210 receives the secondpressurized gas stream 2308 and outputs an expanded gas stream to thesecond inlet 2220. In particular, the second turbo expander 2210 reducesa pressure of the second pressurized gas stream 2308 to produce anexpanded gas stream provided to the heat exchanger 2204. A second outlet2221 of the heat exchanger 2204 corresponds to the second inlet 2220,and the pipeline 2212 may be connected to the second outlet 2221 of theheat exchanger 2204.

In operation, the heat exchanger 2204 cools the first pressurized gasstream 2306 moving therethrough via heat transfer between the firstpressurized gas stream 2306 and the expanded gas stream (output from theturbo expander 2210) in the heat exchanger 2204. This simultaneouslyheats the expanded gas stream in the heat exchanger 2204. As such, theheat exchanger 2204 produces a heated gas stream by heating the expandedgas stream, and the heated gas stream is output from the heat exchanger2204 via the second outlet 2221 toward the pipeline 2212. The heated gasstream produced by the heat exchanger 2204 may be output toward thepipeline 2212 at a pressure and temperature suitable for the pipeline2212. Providing heat exchange between the expanded gas stream and thefirst pressurized gas stream allows the expanded gas stream to be heatedup to a pipeline-suitable temperature and the first pressurized gas flowto be pre-chilled before it is partially liquified.

As illustrated in FIG. 22 , the second turbo expander 2210 may becoupled to the at least one compressor 2216 to supply power 2218generated by the second turbo expander 2210 to the at least onecompressor 2216. The power generated by the second turbo expander 2210may be supplied to the compressor(s) 2216 for operating thecompressor(s) 2216. The at least one compressor 2216 may thus be coupledto one or both of the turbo expander 2206 and the second turbo expander2210. One or both of the turbo expander 2206 and the second turboexpander 2210 may supply power to the at least one compressor 2216.Similar to the coupling between the turbo expander 2206 and thecompressor(s) 2216 described above, the second turbo expander 2210 maybe mechanically or electrically coupled to the compressor(s) 2216 so asto provide mechanical power or electricity for driving the compressor(s)2216.

As illustrated in FIGS. 22-24 , the systems 2200, 2300, and 2400 eachinclude the heat exchanger 2204 with paths therethrough for the LNG feed(e.g., first pressurized gas stream), the pipeline feed (e.g., expandedgas stream), and the chilled vapor feed(s). However, in otherembodiments, only some of these components may be present. For example,the system may not include the pipeline feed and may instead simplyinvolve the heat exchanger 2204 transferring heat between the firstpressurized gas stream and the chilled vapor feed(s). In anotherexample, the system may not include the chilled vapor feed(s) and mayinstead simply involve the heat exchanger 2204 transferring heat betweenthe first pressurized gas stream and the pipeline feed. Thecompressor(s) 2216 and line running from the compressor(s) 2216 to thepipeline 2212 may not be present in some embodiments.

In FIGS. 22-24 , the first pressurized gas stream 2306 (used to produceLNG 2208) is being cooled down in the heat exchanger 2204 while allother feeds (e.g., chilled vapor feeds, expanded gas stream) through theheat exchanger 2204 are being heated. Heat exchange between the chilledvapors/expanded gas stream and the pressurized gas stream 2306 allow theyield of LNG 2208 to be maximized. For example, the heat exchange maycontribute to up to 38% liquefaction of the pressurized gas stream usingonly energy harnessed from the well. The systems in FIGS. 22-24 providemultiple benefits over existing systems used to produce LNG. LNG isoften produced by chilling a gas stream at near-constant pressure, whichrequires external power to compress one or more circulatingrefrigerants. The disclosed system, however, enables the generation ofLNG 2208 by using only the pressure energy available in the feed. Thedisclosed system uses a self-refrigeration process to produce LNG 2208as a byproduct. Additionally, the process does not generate emissions,since the low pressure vapors separated from the feed are not flared.Instead, they are compressed to pipeline pressure, transported to thepipeline, and therefore not wasted.

FIG. 23 illustrates an example system 2300, which is a more detailedversion of the system 2200 in FIG. 22 . In FIG. 23 , the system 2300operates via a single-stage compression process. As such, the system2300 has only one separator 2214 and one compressor 2216. The system2300 may include a cooler 2310 connected between the compressor 2216 andthe pipeline 2212. The cooler 2310 may cool the compressed gas outputfrom the compressor 2216 to a pipeline-suitable temperature. The system2300 may include a pipeline gas mixer 2312 at the intersection of theflow path from the second outlet 2221 of the heat exchanger 2204 and theflow path from the compressor 2216. The pipeline gas mixer 2312 mixesand directs both flows of pipeline-suitable gas to the pipeline 2212.The pipeline gas mixer 2312 may be a simple pipe tee or may include oneor more valves.

FIG. 24 illustrates another example system 2400, which is a moredetailed version of the system 2200 in FIG. 22 . In FIG. 24 , the system2400 operates via a multi-stage compression assembly. The multi-stagecompression assembly includes multiple compressors 2216A, 2216B, 2216C,and 2216D connected in series. Similarly, the system 2400 includes amulti-stage separation assembly including multiple separators 2214A,2214B, and 2214C connected in series. Successive pressure cuts and themultiple separators 2214 on the partially liquified gas stream reducethe amount of power required for operating the VRU.

As illustrated in FIG. 24 , the system 2400 may include four stages ofcompression for recovering vapors into the pipeline 2212. However, anydesired number (e.g., 1, 2, 3, 5, 6, 7, 8, or more) stages ofcompression may be used in other embodiments. The heat exchanger 2204may include multiple vapor inlets 2215A, 2215B, and 2215C, and eachvapor inlet 2215 is connected to one of the multiple separators 2214.The heat exchanger 2204 may similarly include multiple vapor outlets2217A, 2217B, and 2217C, and each vapor outlet 2217 is connected betweena corresponding one of the multiple vapor inlets 2215 and acorresponding one of the multiple compressors 2216. For example, vaporsflow from the last separator 2214A in the series of multiple separators2214, through the vapor inlet 2215A and vapor outlet 2217A to the firstcompressor 2216A in the series of multiple compressors 2216.

The system 2400 may include at least one interstage vapor mixer 2402connected between one of the multiple vapor outlets 2217 and thecorresponding one of the multiple compressors 2216 for mixing vaporsoutput from the vapor outlet 2217 with compressed vapors output from anadjacent compressor 2216. For example, vapors flow from the separator2214B through the vapor inlet 2215B and vapor outlet 2217B to theinterstage vapor 2402A, which mixes the vapors with the vaporscompressed by the first compressor 2216A. The interstage vapor mixer2402A then directs the combined flow of vapors to the second compressor2216B providing the second stage of compression. Each interstage vapormixer 2402 may be a simple pipe tee or may include one or more valves.As illustrated, a cooler (e.g., 2310A, 2310B, 2310C, and 2310D) may beconnected downstream of each compressor (e.g., 2216A, 2216B, 2216C, and2216D) to reduce the temperature for mixing with the next stage ofvapors and/or for bringing the output vapors to a pipeline-suitabletemperature.

The presence and/or number of compressors 2216, the number of separators2214, the presence of a pipeline feed/second turbo expander 2210/secondpressurized gas stream 2308, and the relative amount of the initialpressurized gas stream 2302 split off for LNG production compared topipeline production may all be selected to optimize the efficiency ofthe system. The system disclosed with reference to FIGS. 22-24 may be aclosed system that uses power harnessed from a well to both produce LNG2208 and supply gas to a pipeline 2212 without generating emissions orrequiring an outside power source.

While various embodiments of a separator, gas processing facility,method, and system were provided in the foregoing description, thoseskilled in the art may make modifications and alterations to theseaspects without departing from the scope and spirit of the invention.For example, it is to be understood that this disclosure contemplatesthat, to the extent possible, one or more features of any aspect can becombined with one or more features of any other aspect. As anothernon-limiting specific example, because natural gas is often odorless, asthose of ordinary skill in the art will appreciate it is customary toadd an odorant, such as ethyl mercaptan, so that a gas leak can bedetected anywhere the gas is being processed or consumed. Therefore,such an odorant can be added to any of the gas products produced inaccordance with the present invention. Accordingly, the foregoingdescription is intended to be illustrative rather than restrictive. Theinvention described hereinabove is defined by the appended claims, andall changes to the invention that fall within the meaning and the rangeof equivalency of the claims are to be embraced within their scope.

What is claimed is:
 1. A system, comprising: a heat exchangercomprising: a first inlet for receiving a first pressurized gas stream;and a first outlet for outputting a chilled gas stream produced by theheat exchanger cooling the first pressurized gas stream; a turboexpander connected to the first outlet of the heat exchanger forreceiving the chilled gas stream from the heat exchanger and producing apartially liquified gas stream, the partially liquified gas streamcomprising vapors and LNG; and at least one separator connected to theturbo expander, wherein the partially liquified gas stream is fed intothe at least one separator, and the at least one separator separates thevapors from the LNG.
 2. The system of claim 1, wherein the heatexchanger further comprises: at least one vapor inlet in the heatexchanger connected to the at least one separator for receiving vaporsfrom the at least one separator.
 3. The system of claim 2, furthercomprising: at least one vapor outlet for outputting the vapors from theheat exchanger; and at least one compressor connected between the atleast one vapor outlet of the heat exchanger and a pipeline forcompressing the vapors output from the heat exchanger to a pressuresuitable for the pipeline.
 4. The system of claim 3, wherein the turboexpander is coupled to the at least one compressor, wherein the turboexpander supplies power to the at least one compressor.
 5. The system ofclaim 3, further comprising a cooler connected between the at least onecompressor and the pipeline.
 6. The system of claim 3, wherein: the atleast one compressor is a multi-stage compression assembly comprisingmultiple compressors connected in series; and the at least one separatoris a multi-stage separation assembly comprising multiple separatorsconnected in series.
 7. The system of claim 6, wherein: the at least onevapor inlet comprises multiple vapor inlets each connected to one of themultiple separators; the at least one vapor outlet comprises multiplevapor outlets each connected between a corresponding one of the multiplevapor inlets and a corresponding one of the multiple compressors; and atleast one interstage vapor mixer is connected between one of themultiple vapor outlets and the corresponding one of the multiplecompressors for mixing vapors output from the one of the multiple vaporoutlets with compressed vapors output from an adjacent compressor. 8.The system of claim 1, further comprising: a feed splitter upstream ofthe heat exchanger for splitting an initial gas stream into the firstpressurized gas stream and a second pressurized gas stream; a secondturbo expander connected between the feed splitter and a second inlet ofthe heat exchanger, wherein the second turbo expander receives thesecond pressurized gas stream and outputs an expanded gas stream to thesecond inlet; and a pipeline connected to a second outlet of the heatexchanger, the second outlet outputting a heated gas stream produced bythe heat exchanger heating the expanded gas stream.
 9. The system ofclaim 8, further comprising at least one compressor connected betweenthe heat exchanger and the pipeline for providing compressed gas to thepipeline, wherein the heat exchanger further comprises: at least onevapor inlet for receiving vapors from the at least one separator; and atleast one vapor outlet for outputting the vapors from the heatexchanger, wherein the at least one compressor is connected to the atleast one vapor outlet.
 10. The system of claim 9, wherein the at leastone compressor is coupled to one or both of the turbo expander and thesecond turbo expander, wherein one or both of the turbo expander and thesecond turbo expander supplies power to the at least one compressor. 11.A method, comprising: receiving a first pressurized gas stream into aheat exchanger; cooling the first pressurized gas stream via the heatexchanger to produce a chilled gas stream output from the heatexchanger; expanding the chilled gas stream via a turbo expanderconnected to the first outlet to produce a partially liquified gasstream comprising vapors and LNG; and separating the vapors from the LNGvia a separator connected to the turbo expander.
 12. The method of claim11, further comprising: receiving the vapors from the at least oneseparator into at least one vapor inlet of the heat exchanger; andcooling the first pressurized gas stream via heat transfer between thefirst pressurized gas stream and the vapors in the heat exchanger. 13.The method of claim 12, further comprising: outputting the vapors fromthe heat exchanger via at least one vapor outlet of the heat exchanger;and compressing the vapors output from the heat exchanger via at leastone compressor to output a compressed gas toward a pipeline at apressure suitable for the pipeline.
 14. The method of claim 13, furthercomprising supplying power generated by the turbo expander to the atleast one compressor for operating the at least one compressor.
 15. Themethod of claim 13, further comprising cooling the compressed gas outputfrom the at least one compressor via a cooler connected between the atleast one compressor and the pipeline.
 16. The method of claim 13,wherein: the at least one compressor is a multi-stage compressionassembly comprising multiple compressors connected in series; and the atleast one separator is a multi-stage separation assembly comprisingmultiple separators connected in series.
 17. The method of claim 16,wherein: the at least one vapor inlet comprises multiple vapor inletseach connected to one of the multiple separators; the at least one vaporoutlet comprises multiple vapor outlets each connected between acorresponding one of the multiple vapor inlets and a corresponding oneof the multiple compressors; and the method further comprises mixingvapors output from the one of the multiple vapor outlets with compressedvapors output from a compressor adjacent the corresponding one of themultiple compressors.
 18. The method of claim 11, further comprising:splitting an initial gas stream into the first pressurized gas streamand a second pressurized gas stream; reducing a pressure of the secondpressurized gas stream via a second turbo expander to produce anexpanded gas stream provided to the heat exchanger; cooling the firstpressurized gas stream via heat transfer between the first pressurizedgas stream and the expanded gas stream in the heat exchanger; andoutputting a heated gas stream produced by the heat exchanger heatingthe expanded gas stream toward a pipeline at a pressure suitable for thepipeline.
 19. The method of claim 18, further comprising: receivingvapors from the at least one separator into the heat exchanger;outputting the vapors from the heat exchanger after the vapors areheated; and compressing the vapors output from the heat exchanger via atleast one compressor to output a compressed gas toward the pipeline atthe pressure suitable for the pipeline.
 20. The system of claim 19,further comprising: supplying power generated by one or both of theturbo expander and the second turbo expander to the at least onecompressor for operating the at least one compressor.